ML14176A777
| ML14176A777 | |
| Person / Time | |
|---|---|
| Site: | Robinson  |
| Issue date: | 09/06/1989 |
| From: | Bernhard R, Kellog P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML14176A775 | List: |
| References | |
| TASK-1.A.1.3, TASK-TM 50-261-89-11, GL-82-12, IEB-88-007, IEB-88-074, IEB-88-084, IEB-88-7, IEB-88-74, IEB-88-84, IEB-89-016, IEB-89-16, NUDOCS 8910040163 | |
| Download: ML14176A777 (43) | |
See also: IR 05000261/1989011
Text
p>R
REGU
UNITED STATES
C,V
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report No.:
50-261/89-11
Licensee:
Carolina Power and Light Company
P. 0. Box 1551
Raleigh, NC 27602
Docket No.:
50-261
License No.: DPR-23
Facility Name:
H. B. Robinson
Inspection Conducted:
July 10-July 28, 1989
Inspector/
,7
R..
Bernhard, Team Leader
Date Signed
Team Members: R. Schin
R. Gibbs
J. Mathis
C. Rapp
L. Mellen
Approved by-
PW. Kellogg, Chief
Date Signed
7
Operational Programs Section
Operations Branch.
Division of Reactor Safety
SUMMARY
Scope:
This was a special announced Operational Safety Team Inspection (OSTI). The
OSTI evaluated the licensee's current level of performance in the area of plant
operations.
The inspection included an evaluation of the effectiveness of
various plant groups including Operations, Maintenance, Quality Assurance, and
Engineering.in support of safe plant operations. Plant management's awareness
of, involvement in,
and support of safe
safe plant operation were also
evaluated.
The inspection was divided into the major areas of Operations, Engineering, and
Maintenance. The team placed emphasis on interviews of personnel at all levels,
observations of plant activities and meetings,
extensive control
room
observations, and system walkdowns. The inspectors also reviewed plant
deviation reports, LERs for the current SALP evaluation period, and evaluated
the effectiveness of the licensee's root cause identification; short term and
.programatic
corrective actions, and repetitive failure trending and related
corrective actions.
8910040163 890906
ADOCK 05000261
G
PNU
2
Resul ts:
The
inspection team concluded that Robinson is enhancing current plant
procedures and practices. In the areas examined,
improvements were noted in
many programs, however weaknesses were also discovered. Management is actively
involved in the improvement process at the plant.
Strengths weaknesses,
and enforcement
items noted during the
inspection
included:
Strengths:
Access control to the control room was good.
The practice of rotating operation's watchstations allows personnel to
enhance their knowledge of different areas of the plant..
Contaminated
space in the plant is minimized due to the aggressive
- radioactive leak control program.
The team noted good equipment appearance and housekeeping in the plant.
LER program improvements since the AEOD report were noted.
The draft temporary modifications procedure,
when implemented,
should
improve the current program.
Good control of the maintenance backlog was noted.
Weaknesses:
Independent verification procedures need improvement.
Inadequate freeze protection was noted for a RWST level instrument and
steam rupture
ESF detectors.
In addition,
the auxiliary operators
interviewed did not have an understanding of the heat trace panel
indications and the modes of failure for the heat trace.
Security badges were noted to be improperly worn.
Annunciator Panel Procedures were noted to have deficiencies.
Temperature
inputs for the reactor calorimetric calculation have the
potential for errors due to-the current calibration practices.
Walkdown
of the Service Water
and Component
Cooling Water Systems
discovered discrepancies.
The plant procedure two year review does not have a time requirement for
incorporation or review of comments generated during.the review.
Weaknesses were noted in the Operations Corrective Action Program.
3
The Design Basis Reconstitution Program had weaknesses in the areas of
verification and validation.
There is a lack of a comprehensive Motor Operated Valve test program.
Enforcement Items:
The Auxilliary. Feedwater
System
was found to have NPSH deficiencies
(Violation).
The plant's program for controlling and documenting application of torque
to fasteners is inadequate (Violation).
Records indicated mechanics failed to follow procedures While performing
work using the reviewed work orders (Violation).
The
CCW Heat Exchanger had maintenance performed without an adequate
safety review (Violation).
The ability of the Closed Cooling Water System to perform its design
function with the current level of tube plugging has not been verified
(Unresolved Item).
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- R. Barnett,.Maintenance Supervisor, Electrical
- C. Baucom, Senior Specialist, Regulatory Compliance
- D. Baur, QA Supervisor
- S. Clark, Project Engineer, Configuration Control
- D. Crook, Senior Specialist, Regulatory Compliance
J. Curley, Director, Regulatory Compliance
- C. Dietz, Manager, Robinson Nuclear Project
- J. Eaddy, Jr., Environmental and Chemistry Supervisor
- S. Griggs, Aid, Regulatory Compliance
- R. Hammond, Environmental and RadiationControl
- E. Harris, Director, Onsite Nuclear Safety
- E. Lee, Senior Specialist, Planning and Scheduling
A. McCauley, Principle Engineer, Onsite Nuclear Safety
- R. Morgan, Plant General Manager
- D. Nelson, Maintenance Supervisor, Mechanical
- M. Page, Acting Manager, Technical Support
D. Quick, Manager, Maintenance
D. Sayre, Senior Specialist, Regulatory Compliance
- E. Shoemaker, Senior Engineer, Operations
- J. Sheppard, Manager, Operations
- B. Slone, Document Control Supervisor.
- R. Smith, Manager, Environmental and Radiation Control
- R. Steele, Operations Coordinator
- H. Young, Director, Quality Assurance/Quality Control
Other licensee employees contacted included technicians,
operators,
mechanics, security force members, and office personnel.
NRC Representatives
- L. Garner, Senior Resident Inspector
- K. Jury, Resident Inspector,
NRR Representative
- R. Lo, Project Manager
- Attended exit interview on July 28, 1989
Acronyms used throughout this report are listed in Appendix C.
0II
2
2. Operations (41400, 41707, 61700, 71707, 93802)
To assess the operational safety of the facility, the team performed
extended observations of the control
room activities, with the unit
operating near 100 percent power. The team conducted system walkdowns and
plant tours, and observed operations rounds. In addition, they interviewed
operators, observed shift turnovers, and reviewed operator logs. The team
also reviewed records used for indication or control of plant status for
adequacy and verified operator awareness of their contents.
The team monitored operator performance, control room decorum, awareness
of plant status, response to alarms, and use of procedures. The team also
reviewed engineering evaluations,
system design,
equipment maintenance,
operating procedures, and operator training as related to questions that
arose from observations in the plant.
a. Control Room Observations
The team observed shift turnovers that were conducted efficiently and
effectively. Individual operator turnovers were accomplished, using
turnover checklists with required signoffs. Then an oncoming shift
.meeting was conducted in the control room by the oncoming Shift
Foreman. This meeting addressed plant status, abnormal conditions,
and planned activities.
Operator control of access to the control room was good.
This was
facilitated by the control room arrangement, with the primary access
door at the opposite side of the control room from the RTGB control
area. The Senior Control Operator's desk was located by the control
room door, which made it easy for him to control access.
The RTGB at the controls area, where the Control Operator was stationed,
was clearly marked by use of a different color carpet.
Shift.manning was clearly posted on a board just outside the control
room. Each watch position was listed, along with the name of the on
shift watchstander. Fire brigade assignments were shown. The number
of watchstanders
and their listed qualifications
satisfied NRC
requirements. The Shift Foreman stated that recent training had been
performed to assure that, using none of the watchstanders who were
assigned fire brigade duties,
the remaining watchstanders could
perform a safe shutdown of the plant from outside of the control room
in an event where the control room had to be evacuated.
Operators
stated that there were sufficient numbers of qualified watchstanders
and that overtime work was rarely required. Almost all of the Auxiliary
Operator watchstanders
on all of the shifts were licensed reactor
operators. The plant practice was for
operators to switch watch
stations daily. The watchstation changes. from. Control Operator, to
Inside Auxiliary Operator, Outside Auxiliary Operator, second Reactor
Operator in the control room, and back to Control Operator.
3
This watchstation rotation practice provides enhanced operator awareness
of plant conditions, improved ability to work together, and leads to
an increased feeling of plant ownership. The team considered this
watchstation rotation as an area of strength for the licensee.
The team reviewed lit
or disabled annunciators in the control room.
The RTGB annunciators were.color coded to assist the operator. Twelve
were colored black, indicating they may normally be lit during plant
operation. Four were yellow, indicating urgent operator action was
required if
they became lit,
such as RCP bearing high temperature.
The remainder of about 470 annunciators were white.
Only six white
annunciators were lit - four indicated potentially abnormal conditions
and two were incorrectly lit
(these had WR. stickers attached for
calibration or repair of the annunciators).
- Four unlit white
annunciators had WR stickers attached for maintenance to be accomplished
on the related equipment. , None of the annunciators indicated an
urgent safety problem.
The Control Operator demonstrated adequate
knowledge of each of these conditions, and in each case had initiated
adequate corrective action.
The licensee had no practi-ce of
intentionally disabling annunciators.
Overall, the team considered
that the total number of lit or disabled annunciators was reasonably
small and well controlled.
The team reviewed control room inoperable equipment.
This included
equipment located in or controlled from the control room.,
For each
of these items, operators had initiated a maintenance WR. Out of the
existing total of about 38 such WRs,
the team selected four of the
older ones for further review.
The team found that two of these
four had long unexplained delays in processing of 9 to 13 months.
One had
been
delayed in maintenance planning (WR/JO 88-ACJCI),
waiting for parts to be ordered.
The other was delayed in Engineering (WR/JO
88-AEKC1 and related
EWR 88-324), apparently waiting to be assigned to an engineer.
The
team discussed unexplained delays in WR processing with maintenance
management,
who stated that use of the existing manual
systems for
tracking EWRs and parts orders was difficult and somewhat ineffective.
They stated that computerization of outstanding EWRs and parts orders
would enable more effective management control and follow-up,
and
would help to eliminate long unexplained delays in repairs to equipment.
Throughout this inspection, the operators displayed a professional
attitude concerning the plant equipment and their responsibilities as
operators. The team reviewed operator logs and records, and found
them to be legible, clear,
and complete,
with only rare minor
exceptions.
The on shift operators appeared to be alert and safely
performing plant manipulations. Operators were attentive to their
panels, and control
room decorum
was good.
The control room
operators maintained an orderly appearance and proper behavior.
.4
b.
Independent Verification of System Alignments
The
team
reviewed the
licensee's
procedure for
independent
verification. A review was completed of OP valve lineup checklists
for safety systems, completed tagouts on safety systems, and the I&C
-Safety Related Instrument Valve Line-Up procedure.
Interviews of
operators by the team on this subject were performed.
The team found that the licensee's procedures for and implementation
of independent verification were generally comprehensive and adequate.
Four items for potential improvement were noted:
1) At least- one of the verifiers should look at the ivalve or
breaker. Procedure PLP-030, Independent Verification, Rev. 1,
allows both verifiers to use the same remote indication to
determine the position of a valve.
This eliminates one last
visual check for operability -
an opportunity to detect such
conditions as
a leaking air actuator,
damaged electrical
connections, missing valve handwheel,
or scaffolding over the
equipment.
2) Both verifiers should be separate and independent from each
other.
PLP-030
does not require both verifiers to perform
separate verifications. However, operators stated that they do
typically perform separate independent verifications.
3)-. A valve that has had maintenance performed on it should have its
position verified before returning it to service.
Neither the
independent verification procedure
nor the tagout procedure
require specifically that this be done.
However,
operators
showed that they do perform and record this function.
4) OP-603, Auxiliary Feedwater System, Rev. 17, in Attachment 9.1,
Valve Checklist, does not require independent verification for
valves V2-20A and V2-20B being open.
These are header section
isolation valves, which if closed would prevent AFW flow to the
A steam generator from the motor driven AFW pumps.
PLP-030
requires the position of these valves to be
independently
verified.
These
four
items
for
potential
improvement in independent
verification are identified as inspector follow-up item 89-11-06:
Independent Verification Procedures Should be Improved.
c.
Freeze Protection for ESF and EOP Instruments
While reviewing
MMM-19,
Safety Related Instrument Valve Line-Up
Procedure,
Rev.
6, the team observed that valves for RWST level
transmitters were not included.
The team then reviewed the OP for
the Safety Injection System to see if
the RWST level transmitter
valves were included in that system lineup checklist.
Five valves
for RWST level instruments were included in that procedure - a root
isolation valve, a drain valve, an isolation valve for each of two
level transmitters,
and
an isolation valve for a local level
indicator. Each had independent verification required.
5
To verify that there were not actually more valves for the RWST level
transmitters for use in calibration, the team reviewed drawing no.
5379-1082,
Safety Injection Flow Diagram,
Rev.
26.
That drawing
showed only the root. isolation valve.
The team then inspected the
installed RWST level transmitter piping arrangement.
The installed
valves were all labeled, and were the ones listed in the OP. Adjacent
to each level transmitter and the local level indicator was a removable
pipe plug, which an I&E technician stated was used for calibration.
An
I&E foreman stated that a modification was planned to install
additional valves to facilitate calibration.
While inspecting the RWST level transmitters; located outside near
the RWST,
the team noted that the pipe from the RWST to the two
transmitters was insulated and supplied with two
types of heat
tracing wires. One type looked like copper tubing with approximately
one-forth inch diameter. This heat tracing was connected through
electrical conduits to a nearby heat tracing distribution panel,
FPP-29. The second type of heat tracing looked like small insulated
electrical wire, with a three pronged plug on one end.
An I&C
technician stated that the 'copper tubing'
was the primary heat
tracing, and was old and somewhat unreliable.
The 'electrical wire'
was the backup heat tracing.
To power the backup heat tracing, an
operator or technician would need to run an extension cord.
Three
other freeze protection devices were on the RWST level instruments:
a heated
box around the first level transmitter and the local
indicator, a heated box around the second level transmitter (which
looked like it
had been more recently installed), and a heat traced
pipe connecting the second level transmitter to the first section of
pipe.
The team asked about how the licensee ensured that the RWST level
transmitter piping did not freeze in the winter,
and subsequently
determined that:
1)
The potential for freezing was a real concern. A Shift Foreman
stated that freezing of the RWST level transmitter piping has
happened before and could be detected in the control room. When
the piping froze, the indicated level in the control room changed.
The Control Operator was required to monitor the RWST level
indicators on the RTGB each shift, and therefore was able to
.detect a change in indicated level. Whenever such freezing was
identified, an operator or technician was promptly dispatched
to heat the affected piping.
2) The design of installed indicators for the freeze protection
circuits was inadequate.
The freeze protection -power supply
panel
had 12 indicating lights and 14 circuits.
The
heating circuit (#12) for one of the RWST level transmitters had
no indicating light on the panel.
6
The related level transmitter box heater had no light at all and
the strip heater on the pipe to the level transmitter had a
separate indicating light that was located so that it
was not
readily visible to an operator.
The heating c.ircuit (#14) for
the other RWST level transmitter had an indicating light on the
panel that came on when the circuit was energized.
But this
light was incorrectly labelled #12.
3) The. procedures for monitoring these freeze protection circuits
were inadequate. The only formal monitoring was a weekly PM to
be- performed by I&C technicians during the months of November
through April. A standing memorandum to the Shift Foreman on
Cold Weather Operations directs the Shift Foreman, when outside
temperature is 32 degrees .F or less, to contact I&C to assure
that all freeze protection panels are in service and operating
as necessary. The Auxiliary Operator daily rounds sheets did
not include a required check of any freeze protection. The team
concluded that a weekly check is not frequent enough to ensure
operability,
because the
RWST level
transmitters serve an
important emergency shutdown function. They provide RWST level
indication and low level alarms in the control room that tell
the operators when to switch to recirculation mode of core
cooling. Emergency Operating Procedure Path 1, Rev.
6, dated
January 6, 1989, relies entirely on RWST level indication for
directing the operator to switch to recirculation mode,
where'
pump suctions are taken from the containment sump instead of the
RWST. Failure of the operator to switch to recirculation before
the RWST emptied would result in a loss of NPSH to the safety
injection pumps,
RHR pumps,
and containment spray pumps.
This
in turn could cause all of these pumps to burn up.
The licensee's
TS
do
not address the emergency
shutdown
importance of the
RWST level
transmitters.
In many other
plants, the RWST level transmitters are ESF instruments which
provide an automatic switchover to recirculation. As such, they
are addressed in the related TS with LCO action statements that
include requirements for prompt shutdown of the plant if less
than a minimum number of channels are operable.
The team verified that the two RWST level transmitters are,
powered from different safety related power sources,
one from
instrument bus two and the other from instrument bus three.
4) Operator knowledge of this freeze protection was inadequate.
Two licensed reactor operators who had stood Auxiliary Operator
watches during the last winter stated that they would informally
check freeze protection panels in cold weather.
But both were
not aware that indicating lights on FPP-29 did not include the
freeze protection circuit for at least one RWST
level
transmitter.
7
They thought that, if all indicating lights on FPP-29 were lit,
then all freeze protection circuits powered from that panel were
operating properly.
The I&C weekly
PM contains instructions that
indicate that a lit
bulb does not necessarily mean
an operable
freeze protection circuit, as follows:
normal glow -
circuit okay
bright glow -
circuit shorted
weak glow - circuit'grounded
bulb not burning -
open circuit
Also,
the operators both stated that there were a total of seven
freeze protection panels in the plant.
The
I&C weekly
PM lists
ten freeze protection panels.
The team asked if
any instruments providing an
ESF signal were
subject to freezing.
A Shift Foreman
stated that steam
pressure transmitters,
which provide an automatic ESF signal, are
located outside. They are subject to freezing and have heat tracing
freeze protection.
This freeze protection has
no alarm and is
officially checked only weekly during winter months by I&C technicians
per the freeze protection weekly PM.
The team concluded that a weekly
check of this freeze protection was not frequent enough to ensure
operability. The ESF function is to automatically initiate safety
injection and containment isolation in the event of a steam line break.
This would be sensed by two of three channels of high differential
pressure between any steam generator and the steam header.
The TS
requires that a minimum of two channels be operable,
and with less
than that operable requires that the plant be shut down within eight
hours. A weekly check of freeze protection during cold weather is not
adequate to ensure operability of this ESF function.
Freeze protection of instruments required for emergency shutdown of
the plant is considered an area of weakness. This will be identified
as inspector follow-up item 89-11-07: Freeze Protection Measures for
RWST and Steam Rupture ESF Detectors are Inadequate.
d. Control of Overtime
The team reviewed procedures for the control of overtime, audited
records of work hours for some operators and maintenance technicians,
and interviewed operators about overtime.
The team found that the licensee's policy on overtime, as described
in OMM-01, Operations - Conduct of Operations,
Rev.
22,
and also in
is substantially
less
comprehensive
than
NRC
recommendations described in Generic Letter 82-12,
which revised
Differences include:
8
The licensee's policy places overtime limits on only Shift
Foremen, Senior Control Operators, Control Operators,
and Shift
Engineers. GL82-12 requires that overtime limits apply to all
plant staff who perform safety-related functions (e.g.,
senior
reactor operators,
reactor
operators,
health physicists,
auxiliary operators, and key maintenance personnel).
2) The licensee's policy applies overtime limits only when the
Reactor Coolant System is greater than 200 degrees or when fuel
is being moved within .the
requires overtime limits at all times.
3) The, licensee's policy applies different limits on working hours
than those required by GL82-12.
4)
Additional differences exist in wording of overtime rules.
The history of this item includes:
1) In 1980,
NRC requirements on limiting overtime were issued as
NUREG 0737 Item I.A.1.3.
2)
On February 26, 1981, the licensee submitted to the NRC a policy
on staff working hours to comply with Item I.A.1.3.
3)
On November 15,
1981,
the NRC approved the licensee's overtime
policy.
4)
On June 15,
1982,
the NRC issued Generic Letter 82-12, which
revised Item I.A.1.3.
of NUREG
0737.
In GL82-12,
the
NRC
requirements on overtime policy were substantially changed.
5)
On December 23,
1982,
the licensee responded to GL82-12.
In
that response, the licensee incorrectly stated that the existing
licensee policy on overtime limits was consistent with the
intent of NRC policy as stated in GL82-12.
6)
In December 1983,
EG&G Idaho prepared a report for the NRC on
the status of the licensee's compliance with NUREG 0737 items..
In that report, the licensee's noncompliance with Item I.A.1.3.
was identified, in that the licensee's TS had not been revised
to include overtime limits and that the licensee's policy on
overtime did not comply with NRC requirements as promulgated in
7)
On
May
15,
1985,
the licensee requested a TS revision to
incorporate the overtime policy that was based on the original
1980 NUREG 0737 requirements.
9.
8)
On
September
12,
1985,
the
NRC approved the licensee's TS
revision.
This was based on the 1981
NRC approval of the
licensee's overtime policy.
A team audit of recent records of work hours for a few operators and
maintenance technicians did not reveal use of excessive overtime. In
interviews, operators stated that in past years heavy use of overtime,
especially during outages, had occurred. They also stated that more
recently, substantial reductions in overtime had been made.
They
stated further that even during the last outage, relatively little
overtime for operators or maintenance personnel
had
been used.
Recent management initiatives to reduce overtime appear to have been
effective. However,
as these are informal controls,
the potential
for exceeding the recommendations of Generic Letter 88-12 in the
future exists.
e. Observation of Daily Rounds
An inspector conducted observation of daily rounds for the purpose of
identifying procedural or personnel weaknesses.
No such weaknesses
were noted, however, the following .items were observed:
1)-
Deficiency Tags
A large number of outstanding equipment deficiency tags existed.
These tags.were in areas that are uncontaminated and readily
accessible.
Five deficiency tags were noted to be greater than
one year old of which three were on safety-related equipment.
Discussions.with Operations personal indicated a lack of support
by Mechanical Maintenance as the reason for the number of
outstanding deficiencies.
2) Contamination Control
A lack of contaminated waste trash cans was noted.
When an
operator changed the filter paper on
an air monitor,
the
operator had to walk a considerable distance to properly dispose
of the filter paper. This increased the chance of.dropping the
filter paper and contaminating the area.
More conveniently
located cans,
or small plastic bags to carry the contaminated
paper in could reduce the chance of contamination.
3) Security Badges
The inspector noted security badges were routinely worn below
the waist or were covered by pocket dosimeters
or pens.
Security badges are required to be worn between the shoulders
and waist and not covered. These infractions went unnoticed by
security personnel until informed by the inspector.
10
4)
Industrial Safety
The inspector observed welding and electrical cables passing
through door ways were unprotected.
This allowed the door to
close and pinch these cables causing damage that could lead to
personnel injury. Guard blocks should be placed around cables
passing through doorways to prevent such damage.
Also, the
landing at the entrance to the Spent Fuel Pool was too narrow
and the door opened completely into the stairway.
5) Operator Access to Spaces and Equipment
The team observed that operator access to spaces and equipment
was good. Auxiliary Operators carry keys for emergency access
into locked high radiation areas and through failed security
doors. In addition, the operators carry flashlights and many
ladders are located throughout the plant, in designated storage
racks. A book of system drawings, which were clear and legible,
was available for use by the Auxiliary Operators.
6) Radioactive Leak Control
The plant has a very small amount of contaminated floor area,
less than 1000 square feet, which enhances operator access to
equipment rooms.
A- good program of radioactive leak control
contributes to the small amount of contaminated area. The team
noted that there were very few valves with leaks of radioactive
liquid. Also, the primary coolant leak rate was very low, less
that 0.04 gpm.
7)
Loose Equipment
The team observed loose equipment carts stored near important
plant equipment. A spare breaker on wheels was located in the
4160 volt switchgear room adjacent to breakers 12 and 13, which
supply normal offsite power to vital 480 volt busses E-1 and
E-2.
Other loose carts were in the 4160/480 volt switchgear
room and elsewhere in the plant, near nonsafety equipment.
A
better storage practice for this equipment would be to have it
tied down or otherwise prevented from moving.
8)
Housekeeping
The team observed housekeeping in general to be good. Rooms and
equipment were clean and well painted. Virtually no loose trash
or tools were seen in the plant.
Ladders were stored in
designated racks.
The plant overall appeared clean and orderly.
4.
11
f. Annunciators Panel Procedures (APPs)
The
APPs listed in Appendix D were reviewed for accuracy and
useability. The APPs are kept at the control panel and are readily
accessible by the operators.
However,
the team found these APPs to
contain inconsistent guidance, insufficient description of causes,
incomplete description of actions, did not require verification of
automatic actions, did not differentiate between local and control
room indications or controls, and referenced setpoints not related to
control room instrumentation scales. Examples of these deficiencies
are given in Appendix E. The inspectoralso noted the RCS Pressure
recorder Wide Range scale did not match the chart paper scale.
The
recorder is incorrectly scaled at 0 -
100 while the chart paper is
correctly scaled at 0 -
3000 psig.
Control
room operators. were
unaware of any reason for this difference. The operators also stated
only the chart paper scale is used for determining
RCS pressure.
This recorder is referenced in the Emergency Operating Procedures to
determine Wide Range RCS pressure trend.
The recorder scale should
be changed to match the chart paper scale.
These observations will
be tracked as Inspector Follow-up Item 89-11-08: Annunciator Panel
Procedure Weaknesses.
g.
Instrument Calibration
The
instrument calibration program was reviewed to identify any
weaknesses. Discussions with Instrumentation and Calibration (I&C)
personnel indicates a routine calibration schedule for all instruments
designated as "required."
When asked the criteria for designating
an instrument as required, the team was told if the instrument is
important, i.e. ESF or Technical Specification (TS)
related, it
is
designated as required.
Non-ESF or TS related instruments could
also be designated as required.
No definitive criteria was found
by the team.
Calibration
sheets are retained for
TS
related
instruments only and not all required instruments.
When the team asked how Operations is informed of which instruments
require calibration, the inspector was told Operations is not informed
until the calibration is to be conducted.
Additionally, Operations
is not informed of calibration results and is not required to signoff
after the calibration has been completed.
Calibration for control
room instrumentation is scheduled during refueling only. One exception
to routine calibration was found.
The feedwater temperature computer
points, used by Operations for calorimetric calculations, are calibrated
by engineering staff assigned to the plant computer.
I&C is only
involved in the installation and initial calibration of the RTDs.
The
RTDs are calibrated using a generic calibration curve; not a calibration
curve specific to the installed RTDs.
12
The computer points are not routinely calibrated and are checked only
when Operations observes a difference in readings. When a calibration
is conducted, only the computer points are calibrated, and not the
entire loop including the RTDs.
Calibration of the computer points
only could cause a falsely low temperature value to be used in the
calorimetric-calculation. This could result in reactor power being
unknowingly increased to greater than 100 percent by the operators.
This item will be tracked as Inspector Follow-up Item 89-11-09:
Weakness in Loop Calibration of Feedwater RTD Used in Calorimetric.
h. Service Water System Operations Walkdown
During the Service Water System walkdown with operations the team
observed a number of equipment, procedure and training deficiencies.
The team identified these deficiencies to the.licensee for corrective
actions. The deficiencies are summarized below and are discussed in
detail in Appendix B.
In the Service Water
System walkdown,
the team *used Operations
Procedure OP-903,
System,
Revision 27
and system
drawing G-190199, Revision 29. There were four cases noted where the
drawing was inconsistent with the as-built configuration. There were
21 label plates missing from valves.
A rubber hose was connected
downstream of valve SW-219, which supplies water to a lubricating oil
separator. There was no caution tag or information tag present.
These Items will be tracked as part of Inspector Follow-up Item
89-11-10: Deficiencies Noted in Service Water and Component Cooling
Water Walkdown.
i.
Temporary Changes to Procedures
The
NRC
team
reviewed
the
temporary
change
request
program.
Administrative procedure AP-004, Development, Review, and Approval of
Procedures, Revisions, and Temporary Changes, Revision 28 dated June
8, 1989,
provides guidelines used for initiating temporary changes.
Temporary changes may be implemented for items that do not change the
intent of the procedure.
A temporary change must be deleted or reviewed for permanent revision
by the responsible manager within 21 days from the date the temporary
change was approved. All temporary changes are assigned a control
number and tracked by a temporary change log. The team reviewed the
temporary change log to assure that changes were reviewed in a timely
manner. Few changes were outside the 21-day limit. The coordinator
uses the change log as a reminder to contact responsible personnel
prior to the 21-day temporary change expiration date. One weakness
identified by the team was that many temporary changes had been
implemented prior to a safety evaluation being performed.
The team
observed a low backlog of temporary procedures existed.
PLP-026 provides a plant-wide methodology
for reporting and
investigating significant off-normal conditions.
The Director of
Regulatory Compliance is responsible for developing and maintaining
a data base for tracking and trending significant off-normal conditions.
13
This is discussed further in section 3.a.2.
j.
Periodic Procedure Review
The team reviewed the licensee program for performing a two year
review for operations procedures.
The program is addressed in
procedure AP-004. Each procedure in the Plant Operating Manual (POM)
is reviewed periodically by a person assigned by the approver or his
designee.
The team verified that the licensee has conducted two
year reviews for operating procedures from 1985 to 1989.
Weaknesses identified are following:
-For
those comments
made during two year reviews,
timely
implementation of comments were not performed. Several comments
for 1987 were generated again during 1989 reviews.
AP-004 does
not require a time limit for comment review and incorporation.
This is identified as Inspector Follow-up Item 89-11-11: Lack of
a Time Limit for Incorporation or Evaluation of Comments Made in
Plant Procedure Two Year Review.
-The guidelines used by the reviewer were weak for both the
administrative and technical reviews.
k.
Operations Corrective Action Program
The NRC Team observed the functioning of the licensee's program for
the evaluation of abnormal operating events. This was reviewed to
assess its efficiency in increasing equipment availability through
correct identification of root cause and by initiating the appropriate
corrective action. *OMM-027,
Revision 2, dated June
14,
1989,
establishes guidelines for Operations Corrective Action Program. The
program provides criteria to identify, document, and evaluate off-normal
conditions,
both
significant
and
non-significant.
Off-normal
condition refers to an adverse condition in any category that should
be
corrected,
including
failures, malfunctions, deficiencies,
deviation defective material and equipment,
and non-conformances.
Off-normal
conditions that are classified as significant are
upgraded to the plant program, PLP-026, Corrective Action Program.
PLP-026 provides a plant-wide methodology for reporting and
investigating significant off-normal conditions.
The Director of
Regulatory Compliance is responsible for developing and maintaining
a data base for tracking and trending significant off-normal conditions.
This is discussed further in section 3.a.2.
The team reviewed the operations corrective action tracking system
and off normal condition analysis reports from August 18,
1988 to
July 24, 1989. The following weaknesses were identified:
14
-Closeout of operations corrective actions werenot performed in
a timely manner. Only 13 out of 82 had been completed during the
time period reviewed-.
-Many off normal conditions analysis reports did not.contain a
root-cause analysis.
In some cases this resulted in repeat
events.
-Trending of non-significant off. normal
conditions needs
improvement to prevent repeat events.
The Operations Corrective Action program as outlined in OMM-027,
Revision 2, dated June 14, 1989, requires that off-normal conditions
analysis in the trending program
be periodically evaluated to
determine if any adverse trends exist. The team review revealed that
this was
not being. performed.
This is identified as Inspector
Follow-up Item 89-11-12: Weakness in Operations Corrective Action
Program.
1. 'Operator Aids
The team reviewed the operator aid program to assure authorization,.
documentation and, periodic reviews were performed.
The operations
engineer- is responsible for authorizing the posting and removal of
operator aids. The controlling procedure for operator aids, OMM-016,
Control of Operator Aids, Revision 2, dated March 29, 1988, provides
guidance for using operator aids. -The Operations Engineer performs a
review of the operator aid log index monthly for correctness, and to
verify a continued need for each posted operator aid.
Quarterly the Operation Engineer reviews the operator aid log to
verify that all logged aids exist, ensures there are no. unapproved
pen and ink changes, checks for legibility, and tours the plant to
identify and remove unauthorized OA's.
The team reviewed the OAL from 1985 to 1989 for periodic -review
compliance. There were five cases where operator aids.had been in
effect for longer than two quarters.
The responsible supervisor had
been notified as to the need to incorporate the aid into a permanent
procedure.
The following operator aids were reviewed by the team:
89-01
-Provide guidance for determination of reporting
requirement and notification.
89-03
-Provide instructions for installation of mechanical
level device.
89-04
-Provide instructions for sampling containment vessel
with cart monitors.
15
The reviewed operator aids appeared to be effective tools for providing
additional guidance to the operators. No discrepancies were noted in the
program.
3.
Engineering (37700, 37701, 37702, 92703)
a. Licensee Event Reports
The team reviewed the Licensee's event/failure trending program and
potential .reportable
events/LERs
from January
1, 1988,
to
July 1, 1989, and evaluated-the adequacy of the following:
1) Trending of Similar Events/Failures.
The licensee has no formal trending program that specifically
tracks events/failures which lead
to
LERs.
However, the
licensee has an informal tracking and trending method which
adequately complies with NUREG
1022,
section V, paragraph B,
which addresses the review of Previous Similar Events. The team
discussed this informal method with the members of the
Regulatory Compliance staff who routinely prepare the LERs. The
team concluded that while the program is not formalized, the
program is effective in identifying previous events
and
initiating programatic corrective actions, .when
appropriate.
Additionally, the team reviewed a selected sample of recent LERs
and concluded that the identification of similar events,
although not formal, was adequate.
2) Corrective Actions.
The team reviewed procedure PLP-026, Corrective Action Program,
Revision 2, June 30,
1989,
which addresses the corrective
actions program
including both short-term and programatic
aspects.
The review, in part,
consisted of a review of
screening
criteria,
corrective
action
methodology,
and
organizational involvement. The team discussed the methodology
for determining corrective actions with
the
licensee's
Regulatory Compliance staff.
Additionally, the team reviewed
the corrective actions for a selected sample of recently
completed
LERs
for special
training, required reading,
procedural revisions, program upgrades,
increased surveillance
frequencies, increased preventative maintenance, and human
factor improvements.
The team concluded that in the selected sample of LERs reviewed
the licensee had generally considered the appropriate factors
when determining the scope of corrective actions.
SII
16
3) Root Cause.
The team reviewed procedure PLP-026, Corrective Action Program,
Draft Revision 3, which at the time of this inspection had not
been issued. The team discussed the proposed procedure revision
with the Regulatory Compliance staff.
The-se discussions were
primarily focused on the licensee's self initiated root cause
determination methodology improvements.
The draft procedure
contains an attachment 7.6, Investigation Team Guidance For The
Investigation Process.
This attachment addresses use of an
independent investigation group to determine the root cause of
an event or condition which has been designated as significant,
and was of such a nature that it exceeds the ability of a single
individual
to
resolve.
The
basic. methodology of
this
investigation team was to ensure that evidence required for a
thorough investigation of the event is preserved and has been
gathered as soon as practical after the event.
Additionally,
the procedure provides several possible methods for root cause
analysis. Although this program has not been implemented, the
procedure demonstrates a well conceived, licensee initiated
program
and should provide useful root cause determination
results for complex events. The inspection team concluded the
weaknesses in the current program were adequately addressed in
the revised program. When the revision is issued the program
should be adequate to effectively determine root cause.
4)
1989 LERs
At the time of this inspection the licensee had issued 9 LERs: 89-001,
Hydrogen introduction into station air 89-002
Contractor exceeded dose limits89-004
Inadvertent closure of MSIV 89-006
Loss of EH control power 89-007
OPDT setpoint 89-008
RHR common mode failure 89-009
Relative humidity >70 percent with CV purge
LER 89-04 and 89-07 had previous similar occurrences. The LERs
were of the type that had a more thorough root cause analysis or
corrective action determination been performed on the referenced
events the events that resulted in these LERs might not have
taken place.
The licensee has made some improvement in these
determinations in recent months,
and has proposed some changes
in the methodology for root cause determination.
These changes and recent improvements should reduce the number of
similar events in the future.
17
5)
Event Response Team.
The licensee does not have a formal event response team that
determines root causes for complex events.
However, the
licensee has a pending- procedural revision that provides the
charter and direction for the formation of this team.
This is
discussed in paragraph 3) of this section.
6) Adequacy and Threshold of LERs.
The team reviewed the licensee's LER Handbook, dated June 15,
1988, which was created to provide guidance to the writers and
reviewers of LERs.
The handbook follows the latest guidance
from NUMARK and NUREG 1022, supplement 2, for the preparation of
LERs,
and delineates the threshold, for reportability of LERs.
Additionally, the handbook provides a historical review of the
AEOD identified LER problems at HBR, detailed information about
the required entry for each block of the LERs report form, and
which items/events require
LERs.
Information
regarding the
immediate notification of
NRC,
four hour notification,
and
thirty day notification is provided.
For the sample of recent
LERs reviewed, the handbook was followed by the LER preparers.
The threshold for reportability and information contained within
LERs
has improved significantly since the AEOD report was
issued, and during the time period of the selected LER review.
The LER reports reviewed appear adequate.
Additionally, the
handbook for LER preparation is clear, unambiguous, and contains
all the pertinent information the LER preparer should need to
prepare an adequate LER.
b. Information Notices
The team reviewed a selected sample of recently completed Information
Notices to determine the licensee's review process,
commitment
tracking,
and the adequacy of the internal communications.
The
specific Information Notices reviewed were: 88-814
Defective Shaft Keys In Limitorque Motor
Actuators
88-74
Potential Inadequate performance of ECCS in PWRs
During Recirculation Operation Following a LOCA
88-07
Failure of Air-operated Valves Affecting Safety
Related Systems
89-16
Excessive Voltage Drop in DC Systems
On-site Nuclear Safety procedure, ONSI-1, Operating Experience
Feedback, Revision 5, dated January 5,
1987,
was established to
delineate
the
responsibilities
for
assuring
that operating
information pertinent to plant nuclear safety is. supplied to the
operating and training organizations.
18
This program and the program of the Nuclear Safety Review Unit were
established to meet the requirements of NRC
Task Action Plan,
Item 1.C.5. The specific documents that are screened by ONSI-1 are:
1) Operating Experience Reports for site events
2) NSSS/Vendor Service Bulletins
3) .
Documents from ONS or the NSR Unit that are designated as
warranting Operating Experience Feedback.
4) INPO Significant Operating Experience Reports and Significant
Event Reports.
,5) NRC I. E. Notices
6) Other industry sources deemed appropriate by the Director -
.
The Operating Experience Feedback path for Information Notices was
reviewed. The Information Notices received an initial screening by
On-site Nuclear Safety document coordinator and were dispositioned to
other groups, as applicable. Where it was clear that the item was
not applicable to HBR or was an item that could be easily dispositioned,
the item was closed by On-site Nuclear Safety and the package was
routed for information purposes only to applicable supervision in
other areas.
When further investigation or study was needed,
the
Information Notice was assigned to a responsible engineer, forwarded
from On-site Nuclear Safety to responsible groups for final disposition,
and a formal tracking number,was assigned..
The tracking number is in
the commitment data base and appears to receive adequate management
attention.
The package is returned to the responsible engineer
assigned by On-site Nuclear Safety when the work has been completed
or other appropriate actions have taken-place. The completed package
is reviewed by the responsible engineer and returned to the designated
organizations if the actions are inappropriate. If the package has
been satisfactorily completed, a copy of each evaluation is maintained
by the NSR Unit, and the original of the closed packaged is forwarded
to the 'record storage group for inclusion in permanent plant records.
The team discussed this process with members of the ONS staff, and
reviewed the applicable procedures and the selected packages.
In
general, the disposition of this sample of Information Notices
appears adequate.
The level of documentation
and the tracking
methods are adequate to provide reliable and retrievable records of
the licensee's disposition of Information Notices.
C.
Design Basis Reconstitution
The team reviewed the licensee's self initiated Design Basis
Reconstitution Project. The licensee's definition of the objective
of this program is to structure the current design basis and
calculations/analyses of record, applicable to the plant systems
required for safe shutdown and mitigation,
and control them for
future use.
The critical design parameters, related to the plant
procedures and .hardware,
will be validated against the structure
design basis.
19
The systems that were in the pilot program were AFW,
These systems have been completed, however,
the validation process
has not been completed for the RPS.
Additionally, the Electrical
Power Distribution System and the -Electrical Cable/Raceway DBD have
been completed,
but the validation process was not complete.
The
other systems to be included in the DBD are Component Cooling Water
System,
HVAC System, Service Water System, Nuclear Instrumentation
System,
Residual Heat Removal System,
Incore Instrumentation System, Chemical and Volume Control,
Reactor
Coolant System,
and Reactor Vessel
Level
Instrumentation System.
Only the post accident response portions of HVAC will be included in
the HVAC DBD. The scheduled completion of this program is 1992.
The system's design basis, as defined by CP&L, is abstract in nature
and consists of:
1) System functional Requirements
2)
Regulatory Requirements/commitments relative to system design
3) Original design codes or standards of record, unless clearly
superseded by a regulatory commitment to a later code or
sta-ndard.
The program appears to be primarily for the use of design engineers.
Within the limits of the program, the licensee appears to be expending
sufficient resources to accomplish the Design Basis Reconstitution.
Based on discussions with the design engineers and a review of the
proposed program, the weaknesses in the program are that there is
limited field verification in the validation phase and no apparent
attempt to validate critical system parameters,
such as flow,
temperature,
and pressure.
An additional weakness in the program
is the extended time after a discrepancy is discovered that a
documented operability review is completed. In most cases reviewed,
the operability review was made several months after the discrepancy
was discovered.
This untimely review can lead to a system being
inoperable for an extended period of time without the licensee being
aware of this condition. This is identified as Inspector follow-up
item 89-11-13: Timeliness
of Operability
Reviews
of Problems
Discovered in Design Basis.
The team requested the licensee to verify a single system parameter,
as a demonstration
that design parameter verification was
not
necessary.
The parameter selected was
Condensate
Storage Tank
temperature effects on Auxiliary Feedwater Pump Net Positive Suction
Head.(NPSH) requirements.
After an initial engineering evaluation it
appeared that there may
be insufficient NPSH for the Steam Driven Auxiliary Feedwater Pump,
if the CST is at minimum level.
Subsequent to the onsite inspection,
NPSH concerns led to a plant shutdown on August 22, 1989. Additional
details of the NRC
review and disposition of this issue will be
documented in Inspection Report 50-261/89-18. This issue is identified
as apparent violation 89-11-01.:
AFW System Inoperability Due to
Inadequate NPSH.-
20
The licensee is continuing the investigation of this finding and is
considering changes in the DBD program. This identified as Inspector
Follow-up item 89-11-15: Validation of Critical Design Parameters in
DBD.
d.
UFSAR Discrepancies
During a review of unrelated subjects, the team noted UFSAR Table
2.3.2-2 entry for July minimum
temperature was in error.
This
appears to be a typographical
error.
The discrepancy will be
evaluated by the licensee for revision to the UFSAR in Amendment 8
and will be tracked as SAR change request A8-095. The team reviewed
the
change
request and proposed corrective actions.
The team
determined that there is no safety significance for this errant
entry, as it provides no input to any of the analyzed accidents, nor
to any critical component design. With the issuance of A8-095, this
item is considered closed.
e. Design Change Packages
The team reviewed two recently completed safety-related Design Change
Packages to determine the adequacy of 10CFR50.59 Evaluations. - The
documentation,. work completion,
functional testing, revisions to
affected procedures and drawings, timeliness of completion, and QA/QC
were reviewed.
The packages were-generally complete.
The safety
evaluations did not reference all of the pertinent information for a
complete evaluation, however, the information was contained in the
package. The post modification testing ,specified and performed was
adequate. Portions of the 'packages could not be reviewed due to the
poor quality of the micro film copy.
Generally the packages
indicated that a little more attention to detail in filling out the
required paperwork would be appropriate, but the packages appeared to
adequately accomplish the intended task.
The team reviewed two temporary modifications to determine their
adequacy.
The first temporary modification reviewed was installed as corrective
actions for a finding in the DBD effort.
Temporary Modification 89-709, RHR Sump Level Indication, Revision 1, dated April 13, 1989,
was installed as a result of an SSFI of the Safety Injection System
DBD.
It revealed that during a LOCA, with a 1 percent fuel failure and a
loss of off-site power, if the RHR pump seal should fail, the control
room operator might not have indication that the RHR pit sump was
filling up.
21
The final conclusion was that any accident that was accompanied with
loss of off-site power would cause the sump pumps, and the. level
indication to fail.
The sump pumps and high level alarms would not
function on loss of off-site power,
since they do not have a
safety-related power source. This temporary modification installed
redundant mechanical level indication that will provide interim level
indication outside the RHR pit until a perman.t solution is implemented.
The temporary modification was installed and was scheduled to remain
in effect until the the next refueling outage.
Since temporary
modifications are generally allowed for only a three month period
without a further evaluation, a request for extension was requested.
The modification extension was granted via memorandum on April 13,
1989,
Serial
number 'RNPD/89-1373.
This extension was handled in
accordance with applicable procedures.
The
licensee performed an engineering calculation, 89-04, to
determine the expected off-site dose based on the modification to the
RHR pit and the accumulation of post-accident reactor coolant. There
was a slight increase in the off-site calculated dose,
however, the
licensee judged that this was not a significant increase. Due to the
low probability of.the RWST pipe breaking during the injection phase,
the licensee and NRR agreed that prior to the next refueling outage
the RWST pipe break need not be considered, and hence the source term
for accumulated reactor coolant was not considered for this period
for entry into the RHR pit. The calculation did not account for the
- dose
to the operator that must perform post-accident
manual
manipulation of the cross-connect valve in the RHR pit.
This was
contained in engineering calculation 89-05, with -the agreed upon
exclusion of the accumulation source term. The licensee will provide
motorized, class 1E operators for the cross-connect valves and will
provide safety-related, class 1E sump pumps in each-of the RHR pits.
The interim level indication installation and the existing level
instrumentation are
not seismic.
Since the level
indication
installed was non-seismic, no -credit can be taken for it's
availability post-accident. However, the licensee has demonstrated
that either channel of the independent* level instrumentation,
if
available, can be installed in a timely fashion.
The licensee performed
the required
10CFR50.59
analysis.
The
analysis concluded that this was not an unreviewed safety question,
based in part on their agreement with
NRR,
that based upon
Probabilistic Risk Assessment data, the circumstances that would lead
to this situation prior to the next refueling outage were highly
unlikely.
22
The second temporary modification reviewed, TEM 89-704, Isolation of
S-26,
and S-30, Revision 0, dated February 8,
1989,
isolated the Penetration
Pressurization System to
the
containment penetration bellows assemblies S-24,
S-26,
and S-30.
These bellows are located on the 3 inch steam generator blowdown
lines.
The Penetration Pressurization System's function is to
provide early indication of primary containment penetration leakage.
The team reviewed the 10CFR50.59 analysis for this modification.
While this modification clearly changed equipment and procedures
referenced in the UFSAR,
it does not change the Chapter 15 analyzed
accidents. The isolation of the three leaking penetrations allows
the Penetration Pressurization System to continue to provide it's
intended function for the balance of the penetrations..
g. Temporary Modification Program
The team reviewed the temporary modifications program by selecting a
sample of temporary modifications that were installed during the last
two years and a sample of currently installed temporary modifications.
A list of the temporary modifications examined for the program
review, along with the team's comments are:
Number
Date
Description
Note(s)88-001
2/2/88
SW HVH Piping
2 88-003
6/9/88
Main Steam Piping
2 88-004
6/21/88
FCV-1332C Leak 88-005
7/25/88
Condensate Polisher
1,2 88-006
7/26/88
MS-128 Down Stream Piping 2 88-007
7/28/88
LCV-1508A Flange
.
2 88-010
8/30/88
AFW PI-1425
2 88-700
9/14/88
.10/12/88 Extraction Steam 88-703
1/3/89
SW Temporary Repair
1 88-704
11/24/88
Fuel Handling System
3 88-705
1/21/89
Thermocouples for HVH-4
1,4 88-706
12/23/88 Pipe Cap On RWST Drain
1,4.89-700
1/13/89
RTD for CV Monitoring
1,4 89-701
1/24/89
FT-113 Leak 89-702
1/30/89 *
CVC 1116 Substation
1,4 89-703
-
2/8/89 .
A and B Leakoff Lines
4,4 89-704
2/8/89
1,4 89-705
2/25/89
Steam Turbine
1,4
0II
23
note 1 -
This item is currently installed as a temporary
modification.
note 2 -
The team reviewed Modification and Design Control
Procedure MOD-018,
Temporary Modifications, revision
2, dated December 20,
1988.
Paragraph
5.9,
Extensions, states "If it is desired to extend the TM
beyond the three (3) months time limit, a revision
must be written in accordance with Paragraph
5.8.
All reviews performed on the original TM must be
reperformed to verify the continued need for the TM.
Extension must
be approved prior to expiration of
original TM... If it is known that a TM must remain
installed for an extended period of time, the Plant
General manager may grant a waiver to the
TM three
month
time limit."
These are examples where this
procedure was not followed.
note 3 -
All documentation for this package was lost.
Modification and Design Control
Procedure MOD-018,
Temporary. Modifications,
Revision
2, dated
December 20,
1988.
Paragraph 5.10,
Dis'position of
Records, delineates the records that should have been
sent to the vault for retention as a permanent record.
None of the required records were retained.
note 4 -
Waiver from the three month installation limit was
issued.
For the
majority
of
1989
temporary
modifications, the modifications were issued an
extension.
It is apparent that most
temporary
modifications, as used at HBR, generally are installed,
at least until the next refueling outage.. The
10CFR50.59 evaluations, if performed, do not generally
address the actual period of time the Temporary
Modification is actually installed.
The team reviewed a number of recent QA Nonconformance Reports that
addressed Temporary Modifications, 88/40, 88/41, 88/42,
and 89/002.
These
documents
identified a number
of
discrepancies
and.
nonconformances in the Temporary Modification implementation.
The
licensee has a self initiated improvement program that specifically
addressed these items and the Temporary Modification program in
general.
The team reviewed the draft of Modification and Design
Control Procedure, MOD-018, Temporary Modifications, Draft Revision
4, and MOD-013, Safety Analysis and Review, Draft Revision 5. The
team discussed these procedures and the proposed philosophy changes
that these procedures represent with the responsible engineer and
appropriate levels of management.
The team determined that the
changes in the procedures indicated that the licensee has proposed
significant improvements in the program will address both the teams
concerns and the balance of the unanswered QA nonconformances.
24
The magnitude of these changes warrant further inspection after the
procedures have been implemented. This is identified as inspector
follow-up item 89-11-14: Review Implementation of MOD-18, Revision 4
and MOD-13, Revision 5 in Temporary Modification Program.
i. Engineering Surveillance Testing
The team reviewed a selected sample of Engineering Surveillance-Tests
to determine the compliance with Technical Specification Schedules,
Licensee commitments,
and all applicable codes and standards.
The
test were accomplished in accordance with applicable -procedures,
which were based upon appropriate standards.
The team did not note
any discrepancies in the sample reviewed.
j. QA/QC
The team reviewed a selected sample of QA/QC audits in the areas of
maintenance,
operations,
and modifications.
The specific packages
reviewed were: 89-007,
Technical Specification Surveillance Program,
dated January
18, 1989.89-032, Maintenance Work Requests, dated May 1, 1989.89-003, Modifications, dated January 16,1989.88-088, Maintenance Work Requests, dated October 17, 1988.88-073, Performance of MST's, dated September 13, 1988.88-044, Maintenance and Operational
Surveillance Tests, dated
June 2, 1988.89-044, Maintenance and Operational Surveillance Tests, dated
March 19, 1989.
Very few findings were identified, all of the findings in the sample
reviewed were of the compliance type.
The audits were generally
compliance based.
This review did not identify any specific
deficiencies in the program.
4. Maintenance (62702, 71710)
During this inspection a review of the licensee's maintenance program was
conducted.
25
This review focused primarily on maintenance activities on the Component
Cooling Water System. The systems approach to this review was used in
order to provide a more definitive basis for drawing conclusions concerning
the effectiveness of the program. The review included several broad areas.
A walkdown of the CCW system was conducted in order to determine the overall
material condition of the system. The results of this walkdown are included
in paragraph. e of this section.
Additionally, corrective maintenance,
preventive maintenance, predictive maintenance, system deficiency backlog,
and trending of component failures were included in the review.
The
paragraphs that follow provide the details of the areas reviewed and the
results and conclusions reached concerning the effectiveness of the program.
a.
Corrective Maintenance
In order to assess the effectiveness of the licensee's corrective
maintenance program a number of completed maintenance work request
packages were selected for a detailed technical review. The packages
were selected based on the importance of the components to plant
safety and also in an effort to provide a cross-sectional overview of
the various different types of maintenance activities.
The work
request had all been completed within the past two years.
For some
of the work only the work request was reviewed. For other work, the
entire work package was reviewed, which included, as appropriate, the
associated maintenance procedures,
the vendors technical manual,
calibration records and procedures, material purchase orders and
receipt inspection records,
weld data reports,
post maintenance
testing records,
etc.
A detailed list of the work request and
administrative procedures reviewed are provided in Appendix A. This
review .noted a number of technical problems:
-WR/JO
89-AACYL,
CCW system check valve CC-721C:
This work
request removed the valve bonnet, inspected the valve internals,
and replaced the bonnet. The WR did not specify a torque.value
for the body to bonnet fasteners,
however,
a Torque Wrench
Certificate of Calibration *Sheet attached to the WR indicated
that a torque wrench calibrated at 215 in-lbs had-been used to
perform the work.
The specific torque value for the body to
bonnet fasteners was not documented in the WR nor was torquing
independently inspected or verified.
The licensee concluded
that the fasteners had been -torqued to 215 in-lbs which is the
torque for a 3/8 inch fastener.
Investigation determined that
the valve has 7/16 inch fasteners for which the proper torque is
30 ft-lbs (360
in-lbs).
In
response to this finding, the
licensee issued WR/JO 89-AGYI1 to retorque the fasteners to the
proper value.
-WR/JO
88-AITFI,
system check valve CC-731:
This work
request removed the valve bonnet to support valve testing and
reinstalled the bonnet once the testing was completed.
The WR
referenced corrective maintenance procedure CM-120, which is the
incorrect procedure for work on this valve.
26
MC-120 provides instructions for repairing Anchor Darling type
C48Z swing check valves. The site equipment loading list states
that CC-731 is a Velan check valve.
Even though the wrong
procedure .was specified, the mechanics used the procedure in
performance of the work as evidenced by signoffs made in the
record copy attached to the completed WR. The procedure was not
followed, however, as evidenced by the following: Attachment 8.1
of CM-120 provides extremely high torque values for the body to
bonnet fasteners (1020 or 1650 ft-lbs, depending on fastener size).
A Torque Wrench Certificate of. Calibration attached' to the
completed WR calibrated the torque wrench used in this work to
150 ft-lbs. The specific torque applied to these fasteners was
not documented in the WR nor was there any independent inspection
or verification of the torque applied.
The licensee concluded,
that the actual torque applied was 150 ft-lbs. This torque value
is incorrect for the Velan valve installed in the plant. The
vendor manual for a Velan cast steel valve specifies a torque of
170 ft-lbs for the body to bonnet fasteners. The vendor manual
also prohibits the use of all solvents for cleaning of the fasteners
except acetone, alcohol or Freon PCA.
The WR did not include
this prohibition. As a result, the licensee issued WR 89-AHDHI
to correct the incorrect torque applied to the fasteners of
CC-731.
This also represents a case of failure to follow
procedure.
-WR/JO 89-ABYB1, CCW flange joint between the "B" RCP upper oil
cooler and valve CC-719B: This WR corrected a leak in the
subject flange by disassembly of the flange, installation of a
new gasket, and reassembly. The WR specified a torque value of
150 ft-lbs for the flange fasteners.
The torque applied was
documented on the WR, but there was no independent inspection or
verification of this action. The torque value applied to these
flange fasteners was obtained from a-generic torquing table in a,
Crane vendor manual which bases torque values on fastener size,
material type and desired stress in the fastener. The technical
source for the torque value appeared to be appropriate, however,
this same torque table had a note which stated that actual
torque values obtained without lubricating.the fasteners would
be as much as 50 percent lower than the values indicated in the
table. The WR did not specify any lubrication for the subject
fasteners.
-WR/JO 89-ACRC1, CCW blind flange between valve CC-795J and the
cooler to the' "B" High Head. Safety Injection Pump: This WR
disassembled the flange, installed a new flexatalic gasket, and
reassembled the flange to correct a flange leak.
The torque
value specified for the flange fasteners (45
ft-lbs) was
documented on the WR,
but this action was not independently
inspected or verified.
The technical' source for the torque
value specified by the WR was from a generic torque table in a
Crane vendor manual which bases torque values on fastener size,
27
material type and desired stress in the fastener.. A note to
this table requires lubrication to obtain desired values. The
WR did not provide instructions requiring lubrication .of the
fasteners.
Additionally,
vendor
instructions
for
the
installation of flexatalic gaskets emphasize the importance of
proper gasket compression during installation. The WR did not
provide any instructions for checking of gasket compression,
such as the use of a feeler gage.
-WR/JO
87-AKWN1,
system relief valve CC-791L:
This WR
rebuilt CC-791L including complete disassembly, cleaning, stem
replacement
and reassembly of the valve.
The
and the
associated maintenance procedure (CM-102) did not provide the
vendor manual required assembly torque values for the body to
bonnet fasteners included in section 7.5 of the vendor manual
(Crosby Nozzle Relief Valve Maintenance Manual) and as a result
the fasteners were not torqued to the required torque.
The WR
and
CM-102 did not require lubrication of the 0-rings and
fasteners as required by section 7.5 of the vendor manual.
Paragraphs 7.1.1,. 7.1.11 and 7.3.13 of CM-102 required data to
be recorded concerning the installed relief valve including the
"as found" and "as left" blowdown ring p.osition. This data was
not recorded as required by the procedure.during the.performance
of the work. This is a failure to follow procedure.
As a
result of these findings, the licensee issued WR 89-AHAKI to
rework the valve.
-WR/JO 89-ABIS1, motor operated valve CC-749B: This WR adjusted
the packing on the valve. The WR required the packing gland to
be tightened to a value of 6 ft-1bs. The WR further allowed the
packing torque to be increased in 0.5 ft-lbs increments and
required that planning be notified if the final torque exceeded
7 ft-lbs. The final torque applied in order to stop the packing
leak was 8.5 ft-lbs. The maintenance foreman, not the planner,
was notified of the overtorquing required.
Investigation into
the
final disposition of this deficiency determined
the
following: The packing vendor (Chesterton) provides the licensee
packing torque requirements based on the size of the valve, the
number of packing rings installed and the valves service (system
temperature and pressure).
The vendor allows the licensee to
torque the packing gland to a maximum of 115 percent of the
specified torque before the valve is required to be repacked.
In this case, the final torque (8.5 ft-lbs) exceeded 115 percent
of the specified torque of 6 ft-lbs (115
percent * 6= 6.9
ft-lbs) and additional corrective action was not initiated by
the licensee. As a result of this finding, the licensee issued
WR 89-AGXZ1 to repack the valve.
-WR/JO 89-AATS1,
"C" CCW Pump: This WR disassembled, inspected,
repaired and reassembled the -"C" CCW Pump.
28
The WR and associated maintenance procedure (CM-019)
did not
provide a torque value for the pump casing fasteners. Review of
the vendor manual noted that no torque value was specified by the
vendor for these fasteners, however,
good engineering practice
would dictate that torque values should be provided for all
system closure fasteners to assure proper system integrity.
-WR/JO 89-AATS1, "C" CCW Pump: This WR disassembled, inspected,
repai-red and reassembled the. "C" CCW Pump.
No records of post
maihtenance testing of this pump following the work on this WR
could be found by the licensee.
-WR/JO
88-ADEK1,
CCW manually operated containment isolation
valve CC-737A: This WR corrected a packing leak on this valve.
The WR reported a packing leak on CC-737A and the description of
the deficiency specifically stated "...Be careful, the valve is
very hard to operate-and tightening the packing may just make it
worse."
In spite of this description the packing was adjusted
to eliminate the leakage.
Post maintenance testing,
such as
cycling of the valve to prove proper operation,
was
not
conducted (see WR/JO 88-AESK1).
-WR/JO
88-AESK1,
CCW manually operated containment isolation
valve CC-737A: This WR was issued approximately one month after
WR/JO 88-ADEK1 and reported that CC-737A was extremely hard to
operate.
The corrective action for this WR included removal of
the grease fitting, clean out of old hardened
grease and
regrease of the grease
box and
stem.
No pos-t maintenance
testing was performed following this work.
Approximately one
month after the corrective action to WR/JO 88-AESK1,
WR/JO
88-AFJK1 reported the same "valve hard to operate" problem. The
corrective action for this WR included repacking of the valve.
The post maintenance testing following this WR was done by
performing OST-908 to verify proper valve functioning.
All of the above listed deficiencies were discussed with the licensee.
Discussion of the torquing deficiencies with the mechanical maintenance
supervisor, the supervisor of planning and one of the maintenance
engineers resulted in a conclusion that the types of deficiencies noted
are generic for much of the maintenance work on site which involves
torquing. This conclusion was based on the fact that these personnel
indicated that until about six months to a year ago the site did not
provide torque values to maintenance personnel for accomplishing work.
At about that time it
was noted by the licensee that maintenahce
practices in this area were deficient.
Since that time all torque
values provided have been taken from a generic torquing table out -of
a Crane vendor manual.
As- noted above this practice results in
incorrect torque values being applied to many of the components in the
plant. The lack of adequate procedures to control torquing of system
closure fasteners and the cases where personnel failed to follow
procedures were of specific concern.
29
These deficiencies are identified as Violation 89-11-02: Inadequate
Plant Programs For Controlling and Documenting the Torquing Process,
and Violation 89-11-04:
Failure to Follow Procedures While Performing
Maintenance.
b. Component .Cooling Water Heat Exchangers:
During the.inspection the licensee was asked to provide a list of all
completed corrective maintenance work request which had been completed
on the CCW system within the past two years.
Team review of this
listing noted two work requests (87-AJPT1
and 89-AFQE1)
which had
accomplished plugging of leaking tubes in the CCW heat exchangers.
Because this work would more likely be accomplished under the design
change program rather than as a maintenance task, an investigation
into this area to determine the basis for the number of tubes allowed
to be plugged was conducted.
The investigation determined the
following:
1) Each of the CCW heat exchangers has a total of 1976 tubes.
2) The licensee had plugged 36 tubes in the "B" CCW heat exchanger
and had plugged 190 tubes in the "A" heat exchanger.
3) The licensee had accomplished the tube plugging in accordance with
a maintenance procedure (CM-201) and did not consider that plugging of
the heat exchanger tubes was a design change.
4) The basis for the number of tubes that could be plugged was included
in an analysis which Westinghouse had provided the licensee.
The
licensee had interpreted the Westinghouse analysis as approval to plug
up to 300 tubes in-each heat exchanger.
5) Review of the Westinghouse analysis noted that there was some
technical basis for plugging up *to 100 tubes, based on calculations
supplied from the heat exchanger vendor which showed no significant
degradation
in heat exchanger performance with up to 100 tubes
plugged. However, the final conclusion that up to 300 tubes could be
plugged was not supported by any detailed technical analysis.
The
Westinghouse analysis final conclusion addressed the adequacy of 75
tubes plugged. The review did not address the original design basis
of the heat exchangers.
Further investigation into this area with the licensee determined
that the heat capacity and specifications of the installed heat
exchangers prior to plugging are the same as those described in Table
.9.2.2-1 of the UFSAR. When the licensee started plugging tubes in
the heat exchangers, thereby changing the flow and heat transfer of
an
item described in the UFSAR,
a 10 CFR 50.59 evaluation was
required. A 10 CFR 50.59 evaluation was not performed
by the
licensee. The failure of the licensee to conduct a 10 CFR 50.59
evaluation is a violation of NRC requirements and is identified as
Violation 89-11-03: CCW Heat Exchanger Plugging Performed Without the
Required 10 CFR 50.59 Review.
!10
30
The licensee is currently conducting an evaluation to determine the
operability of the CCW heat exchangers.
Until this item is completed and reviewed, this item will be identified
as unresolved item 89-11-05: CCW Heat Exchanger Adequacy in Performing
Its Intended Design Functions.
c. Maintenance backlog
During the inspection, the team attempted to assess the backlog of
maintenance items which are outstanding.
The
team reviewed the
backlog of work on the Component. Cooling Water system including the
outstanding deficiencies (WR/JOs, EWRs, Field Reports, Nonconformance
Reports and Significant Condition Reports) which existed at the time
of the inspection.
This information was reviewed to assess both the
total number of items outstanding,
and the severity of each item.
The review also assessed the prioritization of the items scheduled
for completion by the licensee.
This information, in conjunction
with the walkdown of the- system (see paragraph e of this section) was
used to complete the overall assessment of the backlog. The walkdown
of the system noted its material condition to be very good, especially
considering the age of the plant. The listing of outstanding deficiencies
on the system was very smal-l (a total of 13 items) and were of no
safety significance. Additionally, the licensee's prioritization was
appropriate. The overall conclusion reached in this area was that the
licensee properly controls the maintenance backlog.
This area is
assessed as a strength.
d.
Preventative and Predictive Maintenance
The preventative maintenance and predictive maintenance programs at
Robinson were also reviewed during this inspection.
The team
evaluated the types of PM or Predictive analysis techniques were in
place, what specific components in the CCW system were maintained or
analyzed by these techniques,
and the frequency of the
PM or
predictive maintenance. The procedures used and the date of the last
PM were also reviewed.
The investigation also verified that
preventative maintenance required in the vendor manuals for the
specific components inspected under item (a.)
were implemented in
site PM procedures.
The conclusion was that the licensee has
adequate programs in place. One weakness identified is that the site
does not have a motor.operated valve testing program currently in
place which attempts
to predict
MOV failures prior to their
occurrence. The licensee has developed a very comprehensive valve
program under a project called the Managed Valve Maintenance Program
(MVMP) which is designed to manage valve performance, not only based
on testing, but also on many other aspects of valve performance.
This program will require a significant amount of resources and a
considerable length of time for implementation.
In the interim the
lack of a motor operated valve testing program is considered a weakness.
31
e. System Walkdown:
Component Cooling Water
The team conducted a partial walkdown of the Component Cooling Water
System with the assistance of an auxiliary operator (approximately 80
percent of the accessible portions of the system were walked down).
The operating procedure OP-306,
Attachment 9.1,
Rev.
12,
Component
Cooling System Checklist, and the system flow diagram 5379-376, Rev.
23 were used to conduct this portion of the inspection.
The team
traced out various portions of the system checking for proper
labeling of components,
material condition of the system,
valves
positioned in the proper position,
and pipe caps installed where
required.
The team observed that the majority of components were properly
labeled with die stamped aluminum labels.
The overall material
condition of the system was very good, and housekeeping and material
condition in the various plant spaces was excellent especially
considering the age of the plant.
Several deficiencies were noted,
however, which were referred to the licensee for corrective action:
.1. Valve CC-851C, root valve to pressure indicator PI-641C, was
found out of position. The valve was open in lieu of closed as
required by the operating procedure and the system flow diagram.
The indicator was for local indication only.
The operator
immediately repositioned the valve in accordance with procedural
requirements.
2. The following valves were not labeled:
CC-862C
CC-794A
CC-795G
CC-869
CC-899
These Items will be tracked as part of Inspector Follow-up Item
89-11-10: Deficiencies Noted in Service Water and Component Cooling
Water Walkdown.
5. Management Meetings (30702)
The team attended regularly scheduled management meetings to evaluate
their effectiveness. Tuesday and Thursday of each week a Unit Managers
Staff Meeting is held. The participants discuss current major items of
interest affecting plant operations and future plans for resolving
problems. At the meeting attended, there was active participation from
all members. The meeting was well focused and not too long to lose its
effectiveness. The staff showed good knowledge of the issues and their
potential impact on plant operations. Responsibility for issue resolution
was clearly defined. The meeting was effective:
A Site Work Activity Coordinator Group Meeting was observed. The meeting
not only discussed the coming day's activities, but also reviewed the next
week's tentative schedule. The meeting was short and concise.
32
Necessary coordination was accomplished without excessive time being taken
in the meeting. Participants interviewed indicated that since' the daily
meetings had been held, coordination on plant activities had improved.
A Robinson Nuclear Project Board of Directors meeting was attended.
The
BOD was formed in October 1988 as a management focus group for long term
plant improvement.
The BOD consists of the manager of the Robinson
Nuclear Project and thirteen members,
mostly supervisors and managers.
The meeting was typified by open,
free exchange of ideas and opinions.
Teamwork and consensus were stressed. Six major goals have been published
and the plant personnel have been briefed on them.
The goals focus on
generation, cost of generation, SALP and INPO ratings, radiation exposure,
and the quality of the workforce and workplace. The group's effectiveness
in reaching their goals cannot yet be determined due to the groups recent
formation. The dates for achievement of the goals vary, but are as late
as December 1993.
4.
Exit Interview
The inspection scope and findings were summarized on July 28,
1989, with
those persons indicated i-n paragraph 1.
The inspector.s described the.
areas inspected and discussed in detail the inspection findings listed
below. The licensee did not identify as proprietary any of the material
provided to or
reviewed by the inspectors during this
inspection.
Dissenting comments were not received from the licensee.
Item number
Status
Description/Reference Paragraph
261/89-11-01
OPEN
VIOLATION - AFW System Inoperable
Due to Inadequate NPSH. (Paragraph 3.c)
261/89-11-02
OPEN
VIOLATION -
Inadequate Plant
Programs
For
Controlling
and
Documenting
the
Torquing
Process.
(Paragraph 4.a)
261/89-11-03
OPEN
VIOLATION - CCW Heat Exchanger
Plugging Performed Without the Required
10CFR50.59 Review. (Paragraph 4.b)
261/89-11-04
OPEN
VIOLATION Failure to Follow
Procedures While Performing
Maintenance. (Paragraph 4.a)
261/89-11-05
OPEN
URI -
CCW Heat Exchanger Adequacy
in Performing
Its
Intended Design
Functions.
(Paragraph 4.b)
261/89-11-06
OPEN
IFI - Independent Verification
Procedures
Should
be
Improved.
(Paragraph 2.b)
33
261/89-11-07
OPEN
IFI -
Freeze Protection Measures
for
and
Steam
Rupture
Detectors are
Inadequate.
(Paragraph
2.c)
261/89-11-08
OPEN
IFI - Annunciator Panel Procedure
Weaknesses. (Paragraph 2.f)
261/89-11-09
OPEN
IFI - Weakness in Loop
Calibration of Feedwater
RTD Used in
Calorimetric.
(Paragraph 2.g)
261/89-11-10
OPEN
IFI - Deficiencies Noted in
Service Water and
Component
Cooling
Water Walkdown.
(Paragraphs 2.h. &
4.e)
261/89-11-11.
OPEN
IFI - Lack of a Time Limit for
Incorporation or Evaluation of Commehts
Made in Plant Procedure Two Year
Review.. (Paragraph 2.j)
261/89-11-12
OPEN
IFI - Weakness in Operations
Corrective Action Program.
(Paragraph
- 2.j)
261/89-11-13
OPEN
IFI - Timeliness of Operability
Review of Problems Discovered in the
DBD. (Paragraph 3.c)
261/89-11-14
OPEN
IFI - Review Implementation of
MOD-18, Revision 4 and MOD-13, Revision
Program.
(Paragraph 3.h)
261/89-11-15
OPEN
IFI - Validation of Critical
Design Parameters in DBD.
(Paragraph
3.c)
Appendix A
The following are a list of Completed Work Request reviewed:
- WR/JO 88-AEPD1
Calibration of FIC-678 alarm switch
- WR/JO 87-AKWN1
Disassembly, inspection, repair, and reassembly of relief
valve CC-791L
- WR/JO 89-AAWW1
Repack of valve CC-712A
- WR/JO 88-AMZI1
EQ repairs to valve CC-716A
- WR/JO 89-ABIS1
Adjustment of packing on-valve CC-749B
- WR/JO 88-AITF1
Open and inspect check.valve CC-731
- WR/JO 89-AACY1
Open and inspect check valve CC-721C
- WR/JO 88-ABZK1
Replacement of solenoid valve CC-739
- WR/JO 88-ABUXI
Replacement of the CCW piping to the "B" RHR pump heat
exchanger
- WR/JO 89-AATS1
Replacement of the "C" CCW pump seals and bearings
- WR/JO 88-ANMR1
Replacement of the "C" CCW pump seals and bearings
WR/JO 87-AJPT1
Repair of,"B" CCW heat exchanger tube leaks
WR/JO 89-ACRC1
Repair of leaking flange upstream of CC-795J
WR/JO 88-AEGE1
.
Replacement of fasteners in the "C" CCW pump and motor
base
WR/JO 88-ADEK1
Repair of packing leak on valve CC-737A
WR/JO 88-AESKI
Correction of a problem with valve CC-737A being hard to
operate
WR/JO 88-AFJK1
Correction of a problem with valve CC-737A being hard to
operate
WR/JO 89-AEFZ1
Valve CC-730 would not cycle during performance of OST-703
WR/JO 89-AEGQ1
Valve CC-730 would not close from the RTGB
WR/JO 88-ABHD1
.Valve CC-716B would not close from the RTGB
WR/JO 88-ADAP1
Valve TCV-144 has a packing leak
WR/JO 88-AJHC1
Valve TCV-144 failed it's stroke time test (OST-703)
WR/JO 89-AEGC1
Valve TCV-144 failed it's stroke time test (OST-703)
WR/JO 89-AFCM1
Valve TCV-144 has a packing leak
WR/JO 89-AFMJ1
Valve TCV-144 failed it's stroke time test (OST-703)
WR/JO 89-ABYB1
Flange leak between the RCP upper oil cooler and valve
CC-7198
The complete .packages for these jobs were reviewed including,
where
appropriate, the associated maintenance procedures,
the vendor technical
manual,
calibration records,. material purchase orders and receipt inspection
records, weld data reports, post maintenance testing records,etc.
The following are a list of the Administrative Procedures reviewed:
MMM-001, Rev. 7
Maintenance Administration Program
MMM-002, Rev. 4
. Maintenance Procedure Preparation
MMM-003, Rev. 19
Maintenance Work Request
MMM-005, Rev. 10
Preventative Maintenance Program
APPENDIX B
Service Water System Walkdown -
Discrepancies Identified
A.
Safety Injection Pump
1. Valve SW-516 not labeled
B. Diesel Generator Room
1. Flow indicator FI-6614A for diesel air dryers not labeled
C. Service Water Booster Pump
1. Check valve SW-561 not labeled
2. Temperature indicator TI-1662A not labeled
3. Drawing does not show installed throttle valve upstream of PSL-1602A
4. Drawing does not show installed vent line upstream of PI-1601A
D. Station and Instrument Air Compressor
1. Valve SW-578 not labeled
2. Valve SW-531 not labeled
3. Valve SW-579 not labeled
4.
PX points were capped off
E. Auxiliary Feedwater Pump and Component Cooling Heat Exchanger
1.
FSL-1633A, inlet to the oil cooler, not labeled
2. SW-115 not labeled
3. TX-1682A not labeled
4. TX-1688A not installed but shown on drawing
F. Steam Driven AFW Pump Oil Cooler
1.
Valve SW-251A not labeled
2. Valve SW-252 not labeled
3.
Valve SW-272 not labeled
4.
Valve SW-259 not labeled
5. PI-6623 contained a blue tag that stated it had been overranged
G.
Feedwater Pump
1. SW-182 not labeled
2. SW-313 not installed but shown on drawing
H.
Turbine Oil Cooler
1. SW-465 not labeled
I. Condensate Pump
2
1. SW-167 not labeled
2. SW-166 not labeled
3. SW-469 not labeled
4. SW-468 not labeled
J.
Seal Water Booster Pumps
1. SW-170 not labeled
2. * A rubber hose was connected downstream of SW-219 which goes over to
the lube oil separator. There was no TM or Caution Tag associated
with this modification.
K. Primary Air Compressor
1. TI-1620 not labeled
APPENDIX C
LIST OF ABBREVIATIONS
Alternating Current
Analysis and Evaluation of Operational Ddata
Administrative Procedure
APP
Annunciator Panel Procedure
ANSI
American Nuclear Standards Institute
Board of Directors
CA
Auxiliary Feedwater System
Component Cooling Water
CFR
Code of Federal Regulations
Carolina Power and Light
Condensate Storage Tank
CV
Containment Volume
Design Basis Document
D/G
Diesel Generator
-DPR
Demonstration Power Reactor
Division of Reactor Safety
EH
Electro Hydraulic
Emergency Operating Procedure
Environmental Qualification
Engineering Safety Features
Engineering Work Request
F
Degrees Fahrenheit
Flow control valve
Ft-lbs
Foot pounds
GL
Generic Letter
HBR
H. B. Robinson
Heating Ventilation and Cooling
Instrument and Controls
IFI
Inspector Follow-up Item
IEN
Inspection and Enforcement Notice
IN
Information Notice
i.n-lbs
Inch pounds
Institute for Nuclear Power Operations
JO
Job Order
Lb
Pounds
LCO
Limiting-Condition for Operation
LER
Licensee Event Report
Loss of Coolant Accident
Motor Operated Disconnects
Monthly Surveillance Test
Motor Operated Valve
Net Positive Suction Head
NRC
Nuclear Regulatory Commission
2
Nuclear Reactor.Regulation
Nuclear Safety Review
Nuclear Steam Supply System
Nuclear Regulation
NV
Chemical Volume and Control System
OA
Operator Aid.
0AL
Operator Aid log
Onsite Nuclear Safety
OP
Operating Procedure
OPDT
Over Pressure Delta Temperature
OST
Operations Surveillance Test
OSTI
Operational Safety Team Inspection
Pressure Indicator
Preventative Maintenance
POM
Plant Operating Manual
Penetration Pressurization System
Pounds per Square Inch Gage
Pressurized Water Reactor
Quality Assurance
Quality Control
.
Reactor Coolant Pump
REV
.
Revision
Resistant Temperature Detector
Reactor Turbine Generator Board
Refueling Water Storage Tank
Systematic Assessment of Licensee Performance
Safety Analysis Report
SF
Shift.Foreman
Safety Injection
Safety Injection System
Safety System Functional Inspection
TM
TS
Technical Specifications
Updated Final Safety Analysi.s Report
Work Request
WR/JO
Work Request/Job Order
Appendix D
APP~s Reviewed:
APP-001-0O8
APP-007-09
APP-007-40
APP-008-14
APP-008-15
APPT007-30
APP-005-19
- *APP-006-06
APP-006-01
APP-006-02
APP-006-09
APP-006-10
APP-006-17
APP-006-18
APP-OO.6-25
ARP-006-26
APP-006-33
APP-006-34
APP-006-41
APP-006-42
APP-00 1-17
.
APP-001-03
APP-CO01-22
APP-002-04
APP-003-27
Appendix E
Examples of APP Weaknesses:
APP-001-08: Requires check of position for valves CC-716A, CC-716B, CC-730 but
not position is given;
CCW flow and CCW Surge Tank level are also required to
be checked but no values are given.
This APP also states to start Standby
Cooling Water Pump but no switch number is given. Without proper guidance, the
operator has no reference to assess system performance.
APP-007-09:
States Standby pump automatically starts but does not require
verification of pump start and does not give switch number.
APP-008-14,15:
APP-008-14 requires check of all turbine valves closed but
APP-008-15 does not.
Since both APPs address a turbine trip, the required.
operator actions should be identical.
APP-005-19: The automatic action given in this APP is not an automatic action
but is a caution that a protective feature is disabled. This APP deviates from
the basic structure of the APPs since automatic actions are expected to occur
versus being disabled.
APP-006-25: This APP has several deficiencies. Automatic actions are given as
'None Applicable.' However, there are several automatic actions thatoccur at
LO-LO level. A reactor trip will occur as will an AFW automatic start. These
are listed as plant effects but are directly related to the LO-LO level.
Since
these are safety-related actions,
the APP
should list these actions as
automatic actions to ensure the operator will make appropriate verifications.
This APP lists several parameters to verify such as SG level, steam flow, and
feedwater flow.
No expected values are given for these parameters
so the
operator is unaware of system performance.
Setpoints are given as percent of
span while control room instrumentation indicates percent of level.
Setpoints
should referenced to the instrument the operator-will use. These deficiencies.
were noted in other APPs that have safety-related functions or actions.
APP-007-38:
This APP references pump trip and alarm setpoints to elevation
while control room instrumentation indicates in percent level.
APP-002-04:
The APP states accumulator pressure should be observed but does
not give a value for accumulator pressure. If accumulator pressure could cause
- an accumulator low level condition, a value should be referenced for the
operator to assess system performance.